It is well known in the art to use rheology modifiers in drilling fluids when drilling wells, such as in the oil and gas industry. Such fluids, or “muds,” serve several functions in the drilling process, including: removal of drilled cuttings, suspension of high specific gravity weight material and fine cuttings, sealing of the sides of the wellbore so as to minimize drilling fluid loss into the formation, provision of a hydrostatic head to prevent blowouts from high pressure fluids into the wellbore or up through the wellbore to the surface, creation of a low-friction surface on the wellbore to facilitate rotation and removal of the drill string as operational conditions require, cooling of the drill bit and lubrication to prevent the drill pipe from sticking during rotation.
An excellent background document summarizing the composition and use of drilling fluids is Remont, Larry J.; Rehm, William A.; McDonald, William M.; and Maurer, William C., “Evaluation of Commercially Available Geothermal Drilling Fluids,” issued by Sandia Laboratories, operated for the United States Energy Research and Development Administration (Nov. 1, 1976) (hereinafter referred to as “Remont et al.”).
Drilling muds traditionally are colloidal suspensions of clays and/or minerals, in either oil or water. Various chemicals can be added to alter, enhance, influence or modify the properties of the suspension, as is well known in the art. For example, a weighting agent, such as barium sulfate, or “barite,” may be added to increase the density of the mud. Viscosifiers may be used to increase viscosity and gel strength. Deflocculants, such as lignosulfonates, prevent formation of clay particles. Filtration control materials, such as soluble polymers or starch, are added to encourage the development of the filter cake on the sides of the wellbore so that a minimal amount of the drilling fluid will enter a permeable formation.
The search for oil and gas has led to the drilling of deeper wells in recent years. Because of the temperature gradient in the earth's crust, deeper wells have higher bottomhole temperatures.
It is therefore broadly recognized in the art that there is a need for a drilling fluid which retains rheological stability throughout a broad temperature range for efficient drilling of these deeper wells.
Because of their better thermal stability, oil-based fluids typically have been used in high temperature applications. However, due to the environmental impact of the disposal of these spent slurries, and the drilled cuttings carried in these slurries, water-based fluids have become more and more the fluid of choice in the industry. Water-based fluids are also preferable in high pressure applications, such as deep wells, because oil-based fluids are more compressible than water-based fluids. This increased compressibility results in increased viscosity.
For a mud to work well in high temperature bottomhole conditions, it must be rheologically stable over the entire range of temperatures to which it will be exposed. This range is generally from ambient temperature to bottomhole temperature. The rheological stability of a mud is monitored by measuring its yield point and gel strengths, in accordance with standard drilling fluid tests, before and after circulation down the wellbore. These standard tests, which include the tests for yield point and gel strengths, are well known in the industry and are described in “Recommended Practice Standard Procedure for Field Testing Water-Based Drilling Fluids,” Recommended Practice 13B-1 (1st ed. Jun. 1, 1990), American Petroleum Institute (hereinafter referred to as “RP 13B-1”).
The prior art has several partial solutions to the difficulties encountered at high temperature operation. One such solution includes the use of polymers instead of clay as viscosifiers. At present, guar gum is typically applied for this purpose in practice. These polymers however are not satisfactory in applications above approximately 120° C.
EP 0 134 084 discloses well drilling fluids based on parenchymal cell cellulose. This material is obtained by the process described in EP 0 102 829, teaching a process characterized by hydrolysis of plant pulp in either strong acid or strong base at high temperatures for short periods in adjunct with mechanical shearing to yield cellulosic and hemicellulosic biopolymers without excessive degradation thereof. A typical process comprises the steps of suspending the sugar beet pulp in an acidic (pH<4.5) or alkaline (pH>10.0) aqueous medium; heating the suspension to a temperature of more than 125° C. (0.5 MPa); keeping the suspension at a temperature of more than 125° C. for a period of between 15 seconds and 360 seconds; subjecting the heated suspension to mechanical shearing in a tube reactor followed by rapid depressurization through small orifices into a zone which is at atmospheric pressure; filtering the suspension and recovering the insoluble fraction which contains the parenchyma cellulose and the soluble fraction (filtrate) which contains the hemicelluloses; treating the cellulose fraction by bleaching with sodium hypochlorite and mechanical defibrillation to produce a parenchyma cellulose paste constituted by cell wall fragments. It is evident from EP 0 134 084 that, although the materials in principle have adequate properties for use in well drilling in general, they are not suitable for use in drilling operation involving very high temperatures, e.g. in excess of 160° C. or 175° C., conditions which are becoming increasingly common in oil well drilling, as explained above.
U.S. Pat. No. 6,348,436 addresses this shortcoming of the EP 0 134 084/EP 0 102 829 materials. According to U.S. Pat. No. 6,348,436, cellulose nanofibrils are used, containing a certain percentage of the non cellulosic acidic polysaccharides retained at the surface of the nanofirbrils having the effect of preventing them from associating with each other. These nanfibrils are obtained by the process described in detail in U.S. Pat. No. 5,964,983. This process comprises the steps of hydrolysing sugar beet pulp at a moderate temperature of 60-100° C., at least one extraction with a base having a concentration of less than 9 wt. % and homogenisation at high pressure and high temperature. This process results in the unraveling of the nanofibrils without breaking them. Electron-microscope observation of these materials indicated that the average cross-section of the nanofibrils was 2-4 nm and the nanofibrils have a length of up to 15-20 μm long.
The reduction of plant fibers to the individual cells, and of plant cells to cellulose fibers and nanofibrils is an energetically intense process, requiring chemical and mechanical action on the plant cells.
Nanofibrililated cellulose materials, furthermore, are notoriously difficult to handle. Systems of unravelled cellulose nanofibrils produce gels at a solids content of not more than 1-2 wt. % in water. Upon concentrating such compositions to higher dry solids amounts, these systems tend to collapse resulting in agglomeration of the nanofibrils. In order to produce fluids having suitable rheological properties from these concentrated nanofibrilated materials again, if possible at all, intensive treatment is required, e.g. by strong agitation. This is a serious draw-back with a view to well drilling applications, where significant amounts of drilling fluids are consumed, which implies that either relatively large volumes (of water) would have to be stored and transported or large amounts of materials would have to undergo intensive treatment at the well drilling site. Not surprisingly, substantive R&D efforts in this field, so far, have not resulted in the actual commercial use of nanofibrilated cellulose materials in well drilling.
Thus, there still remains a need for a well drilling fluid material that is convenient and economical to produce on a large scale and can be used in drilling operations involving high temperatures, such as above 175° C. or 180° C.